Transformers generally consist of copper and/or aluminum conductors, insulated with paper or varnish, wound into a variety of winding configurations, separated by pressboard spacers to allow oil flow for cooling, and a variety of pressboard barriers for insulation between windings and ground. A silicon steel laminated core links the windings. The assembly is contained in a heavy steel tank with porcelain bushings to connect to the windings, external cooling heat exchangers, and various accessories. The transformer is filled with insulating oil to provide insulation and to carry away heat from the windings. Provisions are made for expansion and contraction of the oil with temperature changes due to loading and ambient. In addition, air and moisture are excluded from the system in order to maintain dielectric integrity and avoid excessive aging of the materials.
Starting in the early 1960s, the practice of monitoring selected gases dissolved in the oil to diagnose operating problems inside oil-filled transformers became a normal industry practice. Various types of dielectric or excessive heating problems break down the insulating oil and solid materials into characteristic gases that dissolve in the oil and collect in the head space. It became industry practice for users to take periodic oil samples from transformers for testing in a laboratory to identify developing operating problems. Considerable effort over the years has gone into trying to categorize certain gases and ratios of these gases to interpret the oil samples and diagnose problems. Because of high variability between different samples, different laboratories, different lab tester, it has been generally considered an "art" subject to different diagnoses from different laboratories. An on-line transformer gas monitor has been the "holy grail" for power transformer users.
It is generally known that an arc under insulating oil generates acetylene gas (C.sub.2 H.sub.2) along with a much larger quantity of hydrogen (H.sub.2). It is probable that hydrogen bubbles are produced that rise to the top of the transformer faster than the gas can be absorbed into the oil. It is also probable that acetylene rides up with the hydrogen bubbles and therefore will be present throughout the transformer head space rather quickly. Gases diffuse much faster throughout gas than through oil, and the fault gases are uniformly distributed in the headspace, whereby a sample is representative of the headspace mixture. Also, transformer winding cooling ducts and insulation barriers tend to provide a vertical path for cooling oil flow and for "rising" bubbles in "rising" oil flow to the top of the transformer. This contrasts with a highly restricted and possible totally blocked horizontal oil path in large power transformers with directed oil flow. For fault gases to get from the point of generation deep in the windings to a location on the tank wall where an oil sample is typically taken, or an on-line analyzer may be located, the gases most likely transfer from rising oil to the gas head space first and then back into the oil at the interface. Interfacial transfer takes place in accordance with the relative saturation Ostwald coefficients for the individual gases. Thermosyphon action alone, no pumping, will slowly circulate oil near the head space, it takes quite some time to reach some degree of equilibrium with the head space, throughout the transformer. It may take 24 hours or more for the fault gases caused by an arc deep in the windings to reach the tank wall where an oil sample is taken or an on-line gas analyzer may be located. Pumped oil circulation will reduce this time, however even then significant time will elapse before any of the fault gases generated by the initial arc can be sensed at the tank wall. During this amount of time, a catastrophic failure of the transformer can develop. Close monitoring of the head space gases for rapidly increasing levels of acetylene and hydrogen would provide an indication of arcing and could be used to generate a dangerous condition and/or a trip signal.
Other failure modes in aged transformers that happen due to cumulative effects of aging, shrinkage, loose clamping, and winding deformation are associated with through-faults (short circuits). The tendency is for individual conductors to bend and twist mechanically during through-faults. Failure may occur several days, weeks or months after the "final" through-fault. Failure starts with shorted turn or strands, resulting in very high localized current, not sensed by differential relaying, and there may not be any partial discharge activity involved. There is burning of conductor and strand insulation and generation of CO and ethylene. This may even include acetylene without arcing. Close monitoring of the head space gases after a through-fault could be used to generate an indication of failure and to generate a trip signal. Here again, bubbles and debris may reach some critical stress region and cause a major failure. This can be a high energy arc that causes tank rupture. Through-fault failures are probably the most difficult to detect because deformed winding conductors can be extremely close together and appear normal. Voltage between turns ranges from a few volts to hundreds of volts. The slightest oil space will provide adequate insulation. However, the slightest movement turns the situation into a serious problem. Close monitoring of the head space gases for a sudden spike in CO, ethylene, and possibly acetylene can be sensed as a dangerous and/or trip condition.
Other gases are generated very slowly by low energy partial discharges or pyrolysis of insulating materials that might dissolve into the oil rather than form bubbles. These are typically incipient problems that would be considered cause for caution and merit more frequent and closer monitoring. In general, a "change" in the long-term trend of gassing is cause for alarm. "Unchanging" low levels of gases, other than acetylene, are normally considered as a "normal" operating condition.
Pat. No. 5,659,126 describes a method for monitoring dissolved gases in the electrical insulating oil supply of an electrical transformer in which a blanket of gas containing a fault gas is present in the headspace above the insulating oil supply contained in the transformer. The method includes transferring a sample of the gas from the headspace to a gas chromatograph instrument, and measuring by gas chromatograph techniques the gas concentration level of the fault gases contained in the gas sample. The output from the gas chromatograph is processed by a computing device which calculates the related gas concentration level of the fault gases present in the oil supply. The computing device is informed of a partition function based on Henry's Law and converts the measured fault gas concentration level in the headspace to a measurement of the corresponding concentration level of the same fault gas in the oil supply. The resulting data are used for producing a reading of the fault gas concentration in the transformer oil supply to provide an indication of a specific transformer fault. The problem with measurement of dissolved or headspace gases is that there are many factors, including temperature, pressure, existing degree of saturation, and partitioning coefficients of individual gases that affect the concentration of the dissolved gases present in the oil and the gases in the head space. It is very difficult to sense an unchanging gas condition because of the dynamic changes in gas distribution through out the transformer.
It would be very valuable to have a way to identify normal and cautious operating conditions without having to take into account all of the variables. Certain gases are slowly and consistently generated over the years in all operating transformers. CO.sub.2 is an example. The concentration may vary in the head space as temperature and pressure vary even though the total volume of CO.sub.2 in the transformer is essentially constant on a weekly/monthly basis. Considerable attention has been given over the years to interpreting transformer faults based upon the ratios of the various fault gases. This relates to the different generation rates of the individual gases at specific local oil temperatures. Generally, more than one gas is produced by any fault condition. However, these efforts were typically based upon oil samples tested in a laboratory, not on-line at the transformer. Also, it is typically assumed that equilibrium conditions exist between the gas producing problem, all of the oil in the transformer and between that oil and the head space gases. In reality, it is very doubtful that equilibrium ever exists in an operating transformer because of variations in load, ambient temperature pumped oil flow and thermosyphon oil flow. It is next to impossible to interpret gases this way reliably on a short time basis. CO.sub.2, or an introduced known volume of a tracer gas, can be used as a base reference. By comparing fault and oxygen gases to nitrogen, being essentially 100%, and the varying CO.sub.2 concentration related to temperature, pressure, oil circulation and its saturation characteristic, the varying concentrations of other gases can be compared in a way that reveals whether total gas content in the transformer is changing, plus how fast it is changing, as an indicator of a gas generation condition inside the transformer. The significance of such "true" changes, once identified, is well established by experience in the industry. This would provide a means for reliable determination of normal (green), cautious (yellow) or dangerous (red) operating conditions.